This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present technological advancement. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present technological advancement. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The 4D seismic interpretation method notes the differences in the images or seismic processing products created from seismic data acquired at different times. For example, an initial seismic survey, often referred to as the base survey, might be recorded prior to any hydrocarbon production, then a period of years pass during which hydrocarbons are produced, and then a subsequent monitor seismic survey is recorded. The subsurface seismic reflectivity can change between these two seismic surveys. These differences are typically interpreted to be due to changes in fluid content and pressure in the hydrocarbon reservoir and are used to estimate which parts of the reservoir have been produced and which parts might be produced more efficiently by a different well pattern or fluid injection method. Exemplary discussions of 4D interpretation technology are explained by David H. Johnston (2013) in a tutorial text. Other exemplary discussions of 4D interpretation are found in David H. Johnston (1998, 2000, 2012) and by J. G. F. Stammeijer (2014).
The planning of marine seismic acquisition programs for 4D seismic interpretation can include a definition of repeatability specifications for source and receiver positions to ensure that the target reservoir zone is illuminated consistently between two or more seismic acquisition programs acquired at different times. Differences between seismic images from monitor and base surveys can be due to either differences in the seismic acquisition or differences in earth properties. A primary goal of 4D seismic acquisition design is to minimize the differences due to seismic acquisition so that the differences in the resulting images can be interpreted as changes associated with the earth properties due to hydrocarbon production. A seismic source is defined to be repeatable if the first survey has a source at a specified location and the second survey has an equivalent source within a small spatial tolerance at the same location. The key parameters of interest for this discussion are shown in FIG. 1. FIG. 1 illustrates subsurface zone of interest 101, hydrocarbon reservoir target zone 102, which is to be illuminated by the source and receiver locations; an overburden subsurface anomaly that modifies illumination of the target zone 102 by either a source or receiver, source location 104 associated with the base (initial seismic survey prior to hydrocarbon production) seismic survey, source location 105 associated with the monitor (second seismic survey acquired after hydrocarbon production) survey, receiver location 106 associated with the base seismic survey, and receiver location 107 associated with the monitor seismic survey. The location, size, and medium contrast parameters of anomaly 103 impacts how the seismic acquisition geometry associated with source and receiver locations impacts the illumination of the target zone. Typical medium parameters that impact seismic wave propagation directly are p-wave velocity, shear-wave velocity, density, the Q parameter controlling attenuation and seismic anisotropy. Rock physics transforms are commonly used to translate other medium parameters such as lithology type, shale volume, porosity, and fluid content into the parameters described above. Local stress changes can also impact seismic anisotropy. The maximum allowed difference between the base and monitor survey source locations is a tolerance used to define source location repeatability specifications for 4D seismic acquisition. The maximum allowed difference between the base and monitor receiver locations is a tolerance used to define receiver location repeatability specifications for 4D seismic acquisition. Both repeatability measures (source and receiver) can be used to define the repeatability of each seismic trace associated with a source location and a receiver location. Likewise, a receiver is defined to be repeatable if the first survey has a receiver at a specified location and the second survey has an equivalent receiver within a small spatial tolerance at the same location. 4D seismic surveys can require that source and receiver pairs corresponding to recorded seismic data both are repeatable to within a specified spatial tolerance.
The expense associated with 4D seismic acquisition is dependent upon the size of the spatial tolerances allowed for source and receiver repeatability. If very tight repeatability specifications are required, crews doing seismic acquisition may take much longer and incur much higher expenses to collect the required data. Alternatively, looser repeatability specifications can result in faster data acquisition and lower expenses.
The magnitude of illumination disruptions due to overburden anomalies in the earth relative to a target reservoir zone depend roughly upon the contrast of an anomaly and the size of the anomaly expressed as a solid angle relative to rays emanating from a source or receiver that reach the target. Waves passing through an anomaly can have both timing and amplitude differences compared to waves that propagate through a more homogeneous background medium. Shallow anomalies tend to have large relative contrasts and are often large in terms of solid angles associated with source or receiver positions. The marine 4D seismic acquisition repeatability specifications can be relaxed somewhat if the subsurface near the water bottom has smoothly-varying geology devoid of localized anomalies, but must be very tightly honored if the subsurface near the water bottom has many or complicated anomalies.
Shallow heterogeneities are often the critical factor in determining the maximum allowable discrepancy between spatial locations of sources and receivers in base and monitor surveys. Compare the illumination disruptions of the same size anomalies in FIGS. 2 and 3. The shallow anomaly 103 in FIG. 2 covers a larger solid angle associated with the source illumination than the deeper anomaly 103 in FIG. 3, and therefore is more important for repeatability specifications. FIG. 4 shows how larger anomalies 103 cover a larger solid angle of illumination for a given source location. Larger anomalies also impact more source and receiver locations. FIG. 5 shows how the concerns described above for overburden anomalies with respect to source locations in FIGS. 1-4 also apply to receiver locations.
Conventional seismic streamer data typically do not sample the near surface in shallow water environments with sufficient resolution to evaluate the degree of near-surface heterogeneity. This is partially due to the large spatial gap between the air gun source array and the nearest hydrophones in the streamer cables. In locations with a shallow water bottom, this large distance between the air gun source and the nearest hydrophones in the streamer cables may be on the order of 100 m while the water bottom depth may be less than 50 m. In these situations, the streamer hydrophones do not record a pre-critical water bottom reflection and the shallow subsurface cannot be imaged with high resolution. These issues are discussed by Norris, 2010, and by Anderson et al, 2016. Their work provides examples of acquiring hydrophone data from receivers placed near each marine air gun source component (typically called near field hydrophone or NFH data), doing direct arrival and reflectivity separation, and creating high-resolution images of water bottom and near-water-bottom zones.